Combination well control/string release tool

ABSTRACT

The present disclosure generally relates to a well control/string release tool  70   a  and methods using the tool. The well control/string release tool  70   a  may be attached to a workstring  9  while performing well control procedures. The well control/string release tool may be used to release the workstring  9  attached thereto in a controlled manner in the event of critical emergency well control. A well control/string release tool includes a release sub  204 , a handling sub  202,  and one or more load bearing elements  228  selectively coupled between the release sub  204  and the handling sub  202.

BACKGROUND OF THE DISCLOSURE Field of the Disclosure

The present disclosure generally relates to apparatus and methods forreleasing strings of tubular in a controlled manner in the event ofcritical emergency well control.

Description of the Related Art

In wellbore construction and completion operations, a wellbore is formedto access hydrocarbon-bearing formations (e.g., crude oil and/or naturalgas) by the use of drilling. Drilling is accomplished by utilizing adrill bit that is mounted on the end of a drill string. To drill withinthe wellbore to a predetermined depth, the drill string is often rotatedby a top drive or rotary table on a surface platform or rig, and/or by adownhole motor mounted towards the lower end of the drill string.

Deep water off-shore drilling operations are typically carried out by amobile offshore drilling unit (MODU), such as a drill ship or asemi-submersible, having the drilling rig aboard and often make use of amarine riser extending between the wellhead of the well that is beingdrilled in a subsea formation and the MODU. The marine riser is atubular string made up of a plurality of tubular sections that areconnected in end-to-end relationship. The riser allows return of thedrilling mud with drill cuttings from the hole that is being drilled.The marine riser is also adapted for being used as a guide means forlowering equipment (such as a drill string carrying a drill bit) intothe hole.

After drilling to a predetermined depth, the drill string and drill bitare removed and a section of casing is lowered into the wellbore. Anannulus is thus formed between the string of casing and the formation.The casing string is temporarily hung from the surface of the well. Acementing operation is then conducted in order to fill the annulus withcement. The casing string is cemented into the wellbore by circulatingcement into the annulus defined between the outer wall of the casing andthe borehole. The combination of cement and casing strengthens thewellbore and facilitates the isolation of certain areas of the formationbehind the casing for the production of hydrocarbons.

Hydrocarbon may enter the wellbore before casing is complete when theformation pressure is higher the pressure of the liquid column in thewellbore or when lowering the casing string causing the well pressure toincrease and fractures sidewalls of the wellbore. Therefore, wellcontrol procedures may be performed during casing to preventhydrocarbons from the formation from entering the wellbore or evenescape to the surface through the wellbore. In the emergency event thatthe hydrocarbon cannot be controlled, the wellbore has to be closed out.To close out the wellbore, a blowout preventer shear ram positioned atthe wellhead is usually used to cut the strings. However, blowoutpreventer shear rams cannot cut through casing strings. Traditionally, astring of drill pipes is used to lower the casing string below theblowout preventer shear ram before the well can be closed. For anoff-shore drilling operation, thousands of feet of drill string has tobe made up on deck to lower the casing string before the well can beclosed. Making up the drill string may take considerable time and notefficient during emergency well control situations.

Therefore, there is a need for apparatus and methods for efficientemergency well control.

SUMMARY OF THE DISCLOSURE

The present disclosure generally relates a well control/string releasetool for emergency well control and methods for emergency well control.

One embodiment provides a well control/string release tool including arelease sub, a handling sub, and one or more load bearing elementsselectively coupled between the release sub and the handling sub.

Another embodiment provides a method for operating a well includingattaching a well control/string release tool to a workstring, andperforming a well control procedure with through the well control/stringrelease tool.

Another embodiment provides a drilling system includes a rig, and a wellcontrol/string release tool disposed on a floor of the rig. The wellcontrol/string release tool comprises a release sub, a handling sub, andone or more load bearing elements selectively coupled between therelease sub and the handling sub.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the presentdisclosure can be understood in detail, a more particular description ofthe disclosure, briefly summarized above, may be had by reference toembodiments, some of which are illustrated in the appended drawings. Itis to be noted, however, that the appended drawings illustrate onlytypical embodiments of this disclosure and are therefore not to beconsidered limiting of its scope, for the disclosure may admit to otherequally effective embodiments.

FIGS. 1A-1C illustrate a drilling system in a casing mode, according toone embodiment of this disclosure.

FIG. 2A is a schematic sectional view of a well control/string releasetool according to one embodiment of the present disclosure.

FIG. 2B is a schematic sectional view of the well control/string releasetool in well control mode.

FIG. 2C is a schematic sectional view of the well control/string releasetool in a string release mode.

FIG. 3 is a schematic sectional view of a well control/string releasetool having a drill pipe adaptor.

FIG. 4 is a flow chart of a method for well control and string releaseaccording to one embodiment of the present disclosure.

FIGS. 5A-5B are schematic sectional views of a well control/stringrelease tool according to another embodiment of the present disclosure.

FIGS. 6A-6B are schematic sectional views of a well control/stringrelease tool according to another embodiment of the present disclosure.

FIGS. 7A-7C schematically illustrates a well control/string release toolaccording to another embodiment of the present disclosure.

FIGS. 8A-8C schematically illustrates a well control/string release toolaccording to another embodiment of the present disclosure.

FIGS. 9A-9B schematically illustrates a well control/string release toolaccording to another embodiment of the present disclosure.

DETAILED DESCRIPTION

The present disclosure generally relates to a well control/stringrelease tool and methods using the tool. The well control/string releasetool may be attached to a workstring while performing well controlprocedures. The well control/string release tool may be used to releasethe workstring attached thereto in a controlled manner in the event ofcritical emergency well control. A well control/string release toolincludes a release sub, a handling sub, and one or more load bearingelements selectively coupled between the release sub and the handlingsub.

FIGS. 1A-1C illustrate a drilling system 1 in a casing mode, accordingto one embodiment of this disclosure. The drilling system 1 may includea mobile offshore drilling unit (MODU) 1 m, such as a semi-submersible,a drilling rig 1 r, a fluid handling system 1 h, a fluid transportsystem 1 t, a pressure control assembly (PCA) 1 p, and a workstring 9.

The MODU 1 m may carry the drilling rig 1 r and the fluid handlingsystem 1 h aboard and may include a moon pool, through which drillingoperations are conducted. The semi-submersible MODU 1 m may include alower barge hull which floats below a surface (aka waterline) 2 s of sea2 and is, therefore, less subject to surface wave action. Stabilitycolumns (only one shown) may be mounted on the lower barge hull forsupporting an upper hull above the waterline 2 s. The upper hull mayhave one or more decks for carrying the drilling rig 1 r and fluidhandling system 1 h. The MODU 1 m may further have a dynamic positioningsystem (DPS) (not shown) or be moored for maintaining the moon pool inposition over a subsea wellhead 10.

Alternatively, the MODU may be a drill ship. Alternatively, a fixedoffshore drilling unit or a non-mobile floating offshore drilling unitmay be used instead of the MODU. Alternatively, the wellbore may besubsea having a wellhead located adjacent to the waterline and thedrilling rig may be located on a platform adjacent the wellhead.Alternatively, the wellbore may be subterranean and the drilling riglocated on a terrestrial pad.

The drilling rig 1 r may include a derrick 3, a floor 4 f, a rotarytable 4 t, a spider 4 s, a top drive 5, and a hoist. The top drive 5 mayinclude a motor for rotating the workstring 9. The top drive motor maybe electric or hydraulic. A frame of the top drive 5 may be linked to arail (not shown) of the derrick 3 for preventing rotation thereof duringrotation of the workstring 9 and allowing for vertical movement of thetop drive 5 with a traveling block 11 t of the hoist. The top driveframe may be suspended from the traveling block 11 t by a drill stringcompensator 8. The traveling block 11 t may be supported by wire rope 11r connected at its upper end to a crown block 11 c. The wire rope 11 rmay be woven through sheaves of the blocks 11 c, and extend to drawworks12 for reeling thereof, thereby raising or lowering the traveling block11 t relative to the derrick 3.

The drill string compensator may 8 may alleviate the effects of heave onthe workstring 9 when suspended from the top drive 5. The drill stringcompensator 8 may be active, passive, or a combination system includingboth an active and passive compensator.

Alternatively, drill string compensator 8 may be disposed between thecrown block 11 c and the derrick 3. Alternatively, a Kelly and rotarytable may be used instead of the top drive 5.

When the drilling system 1 is in a deployment mode, an upper end of theworkstring 9 may be connected to the top drive quill, such as bythreaded couplings. The workstring 9 may include an inner casing string15. The inner casing string 15 may include joints of casing 15 j, afloat collar 15 c, and a guide shoe 15 s. The inner casing componentsmay be interconnected, such as by threaded couplings.

The fluid transport system 1 t may include an upper marine riser package(UMRP) 16 u, a marine riser 17, a booster line 18 b, and a choke line 18k. The riser 17 may extend from the PCA 1 p to the MODU 1 m and mayconnect to the MODU 1 m via the UMRP 16 u. The UMRP 16 u may include adiverter 19, a flex joint 20, a slip (aka telescopic) joint 21, and atensioner 22. The slip joint 21 may include an outer barrel connected toan upper end of the riser 17, such as by a flanged connection, and aninner barrel connected to the flex joint 20, such as by a flangedconnection. The outer barrel may also be connected to the tensioner 22,such as by a tensioner ring.

The flex joint 20 may also connect to the diverter 19, such as by aflanged connection. The diverter 19 may also be connected to the rigfloor 4 f, such as by a bracket. The slip joint 21 may be operable toextend and retract in response to heave of the MODU 1 m relative to theriser 17 while the tensioner 22 may reel wire rope in response to theheave, thereby supporting the riser 17 from the MODU 1 m whileaccommodating the heave. The riser 17 may have one or more buoyancymodules (not shown) disposed therealong to reduce load on the tensioner22.

The PCA 1 p may be connected to the wellhead 10 located adjacent to afloor 2 f of the sea 2. A conductor string 23 may be driven into theseafloor 2 f. The conductor string 23 may include a housing and jointsof conductor pipe connected together, such as by threaded couplings.Once the conductor string 23 has been set, a subsea wellbore 24 may bedrilled into the seafloor 2 f and an outer casing string 25 may bedeployed into the wellbore. The outer casing string 25 may include awellhead housing and joints of casing connected together, such as bythreaded couplings. The wellhead housing may land in the conductorhousing during deployment of the casing string 25. The outer casingstring 25 may be cemented 26 into the wellbore 24. The casing string 25may extend to a depth adjacent a bottom of the upper formation 27 u. Thewellbore 24 may then be extended into the lower formation 27 b using adrill string (not shown).

The upper formation 27 u may be non-productive and a lower formation 27b may be a hydrocarbon-bearing reservoir. Alternatively, the lowerformation 27 b may be non-productive (e.g., a depleted zone),environmentally sensitive, such as an aquifer, or unstable.

The PCA 1 p may include a wellhead adapter 28 b, one or more flowcrosses 29 u,m,b, one or more blow out preventers (BOPs) 30 a,u,b, alower marine riser package (LMRP) 16 b, one or more accumulators, and areceiver 31. The LMRP 16 b may include a control pod, a flex joint 32,and a connector 28 u. The wellhead adapter 28 b, flow crosses 29 u,m,b,BOPs 30 a,u,b, receiver 31, connector 28 u, and flex joint 32, may eachinclude a housing having a longitudinal bore therethrough and may eachbe connected, such as by flanges, such that a continuous bore ismaintained therethrough. The flex joints 21, 32 may accommodaterespective horizontal and/or rotational (aka pitch and roll) movement ofthe MODU 1 m relative to the riser 17 and the riser relative to the PCA1 p.

Each of the connector 28 u and wellhead adapter 28 b may include one ormore fasteners, such as dogs, for fastening the LMRP 16 b to the BOPs 30a,u,b and the PCA 1 p to an external profile of the wellhead housing,respectively. Each of the connector 28 u and wellhead adapter 28 b mayfurther include a seal sleeve for engaging an internal profile of therespective receiver 31 and wellhead housing. Each of the connector 28 uand wellhead adapter 28 b may be in electric or hydraulic communicationwith the control pod and/or further include an electric or hydraulicactuator and an interface, such as a hot stab, so that a remotelyoperated subsea vehicle (ROV) (not shown) may operate the actuator forengaging the dogs with the external profile.

The LMRP 16 b may receive a lower end of the riser 17 and connect theriser to the PCA 1 p. The control pod may be in electric, hydraulic,and/or optical communication with a control console 33 c onboard theMODU 1 m via an umbilical 33 u. The control pod may include one or morecontrol valves (not shown) in communication with the BOPs 30 a,u,b foroperation thereof. Each control valve may include an electric orhydraulic actuator in communication with the umbilical 33 u. Theumbilical 33 u may include one or more hydraulic and/or electric controlconduit/cables for the actuators. The accumulators may store pressurizedhydraulic fluid for operating the BOPs 30 a,u,b. Additionally, theaccumulators may be used for operating one or more of the othercomponents of the PCA 1 p. The control pod may further include controlvalves for operating the other functions of the PCA 1 p. The controlconsole 33 c may operate the PCA 1 p via the umbilical 33 u and thecontrol pod.

A lower end of the booster line 18 b may be connected to a branch of theflow cross 29 u by a shutoff valve. A booster manifold may also connectto the booster line lower end and have a prong connected to a respectivebranch of each flow cross 29 m,b. Shutoff valves may be disposed inrespective prongs of the booster manifold. Alternatively, a separatekill line (not shown) may be connected to the branches of the flowcrosses 29 m,b instead of the booster manifold. An upper end of thebooster line 18 b may be connected to an outlet of a booster pump 44. Alower end of the choke line 18 k may have prongs connected to respectivesecond branches of the flow crosses 29 m,b. Shutoff valves may bedisposed in respective prongs of the choke line lower end. An upper endof the choke line 18 k may be connected to an inlet of a mud gasseparator (MGS) 46.

A pressure sensor may be connected to a second branch of the upper flowcross 29 u. Pressure sensors may also be connected to the choke lineprongs between respective shutoff valves and respective flow crosssecond branches. Each pressure sensor may be in data communication withthe control pod. The lines 18 b,k and umbilical 33 u may extend betweenthe MODU 1 m and the PCA 1 p by being fastened to brackets disposedalong the riser 17. Each shutoff valve may be automated and have ahydraulic actuator (not shown) operable by the control pod.

Alternatively, the umbilical 33 u may be extended between the MODU 1 mand the PCA 1 p independently of the riser 17. Alternatively, theshutoff valve actuators may be electrical or pneumatic.

The fluid handling system 1 h may include one or more pumps, such as acement pump (not shown), a mud pump 34, and the booster pump 44, areservoir, such as a tank 35, a solids separator, such as a shale shaker36, one or more pressure gauges 37 k,m,r, one or more stroke counters 38m, one or more flow lines, such as cement line 14, mud line 39, andreturn line 40, one or more shutoff valves 41 k, a cement mixer (notshown), a well control (WC) choke 45, and the MGS 46. When the drillingsystem 1 is in a drilling mode (not shown), the tank 35 may be filledwith drilling fluid, such as mud (not shown). In the deployment mode,the tank 35 may be filled with conditioner 43. In the cementing mode,the tank 35 may be filled with chaser fluid 47. A booster supply linemay be connected to an outlet of the mud tank 35 and an inlet of thebooster pump 44. The choke shutoff valve 41 k, the choke pressure gauge37 k, and the WC choke 45 may be assembled as part of the upper portionof the choke line 18 k.

A first end of the return line 40 may be connected to the diverteroutlet and a second end of the return line may be connected to an inletof the shaker 36. The returns pressure gauge 37 r may be assembled aspart of the return line 40. A lower end of the mud line 39 may beconnected to an outlet of the mud pump 34 and an upper end of the mudline may be connected to the top drive inlet. The mud pressure gauge 37m may be assembled as part of the mud line 39. A lower end of a mudsupply line may be connected to an outlet of the mud tank 35 and anupper end of the mud supply line may be connected to an inlet of the mudpump 34.

The float collar 15 c may include a housing, a check valve, and a body.The body and check valve may be made from drillable materials. The bodymay have a bore formed therethrough and the torsional profile femaleportion formed in an upper end thereof for receiving a wiper plug duringcementing. The check valve may include a seat, a poppet disposed withinthe seat, a seal disposed around the poppet and adapted to contact aninner surface of the seat to close the body bore, and a rib. The poppetmay have a head portion and a stem portion. The rib may support a stemportion of the poppet. A spring may be disposed around the stem portionand may bias the poppet against the seat to facilitate sealing. Theguide shoe 15 s may include a housing and a nose made from a drillablematerial. The nose may have a rounded distal end to guide the innercasing 15 down into the wellbore 24.

During deployment of the inner casing string 15 may be lowered by thetraveling block 11 t and a conditioner may be pumped into the workstringbore by the mud pump 34 via the mud line 39 and top drive 5. Theconditioner may flow down the workstring bore and the liner string boreand be discharged by the guide shoe 15 s into the annulus 48. Theconditioner may flow up the annulus 48 and exit the wellbore 24 and flowinto an annulus formed between the riser 17 and the workstring 9 via anannulus of the LMRP 16 b, BOP stack, and wellhead 10. The conditioner 43may exit the riser annulus and enter the return line 40 via an annulusof the UMRP 16 u and the diverter 19. The conditioner may flow throughthe return line 40 and into the shale shaker inlet. The conditioner maybe processed by the shale shaker 36 to remove any particulatestherefrom.

The drilling system 1 may include a well control/string release tool 70for performing well control and string release during well controlsituations. During normal operation, the well control/string releasetool 70 may be disposed on the floor 4 f. During well control, the wellcontrol/string release tool 70 may be installed on the top of theworkstring 9, especially when a casing joint 15 j on the workstring 9 iscross with the blowout preventers 30 a. The well control/string releasetool 70 allows conventional well control procedures to be performedwhile attached to the workstring 9. In case of emergency, the wellcontrol/string release tool 70 may be activated to release theworkstring 9 from the rig 1 r. The released workstring 9 can then fallunder gravity so that all casing joints 15 j fall below the blowoutpreventer 30 a in a matter of seconds. The blowout preventer 30 a canthen close out the wellbore.

FIG. 2A is a schematic sectional view of the well control/string releasetool 70. The well control/string release tool 70 may include a handlingsub 202 and a release sub 204 coupled to the handling sub 202. Therelease sub 204 may be selectively released from the handling sub 202.

The handling sub 202 may include a landing sleeve 206 encasing a releasesleeve 208. The release sleeve 208 may be coupled to the landing sleeve206 by one or more pins 214. The one or more pins 214 may be insertedthrough openings through the landing sleeve 206 to a groove 212 formedon an outer surface of the release sleeve 208. The groove 212 allows therelease sleeve 208 to slide relative to the landing sleeve 206. Thehandling sub 202 further includes a lock collar 218. The lock collar 218may be inserted between the landing sleeve 206 and the release sleeve208 to prevent the release sleeve 208 from sliding long the landingsleeve 206, thus, lock the release sleeve 208 in position. The lockcollar 218 may include two or more sections.

A tubular connector 216 may be coupled to the release sleeve 208. Thetubular connector 216 allows the handling sub 202 to interface with atool on the rig, such as a casing running tool, a drill pipe runningtool, a power swivel, or the like. In FIG. 2A, the tubular connector 216is designed to interface with a casing running tool. The tubularconnector 216 may be coupled to the release sleeve 208 by a fast lock oran ACME connector.

The release sub 204 may include a tool joint 220 for connecting with aworkstring, such as a casing string, a drill pipe string, or otherstrings. In FIG. 2A, the tool joint 220 is connected to a casing joint15 j by a casing coupling 222. Other adaptors may be used to connect thetool joint 220 to other strings. The release sub 204 has a tubularsection 224 extending from the tool joint 220. The tubular section 224may be disposed inside the release sleeve 206 and selectively attachedto the handling tool 202 by a weight bearing structure. In oneembodiment, the weight bearing structure includes a plurality of loadbearings 228 selectively disposed in grooves 226 formed on an outersurface of the tubular section 224 and through holes 230 formed throughthe release sleeve 208. A plurality of grooves 232 are formed in aninner surface of the landing sleeve 206 for receiving the plurality ofload bearings 228 during tool release.

In one embodiment, a drill pipe connection 234 may extend from thetubular section 224. The tubular section 224 and the drill pipeconnection 234 may form an inner volume 238 to allow fluid communicationwith an inner volume 9 i of the workstring 9 during well control. Anoptional Kelly valve 236 may be attached to the drill pipe connection234 to selectively close the inner volume 238.

In one embodiment, an anti-rotation component 240 may be disposedbetween the landing sleeve 206 of the handling sub 202 and the tooljoint 220 of the release sub 204 to prevent the release sub 204 fromrotating relative to the handling sub 202. The anti-rotation component240 allows torque transfer from the handling sub 202 to the workstring 9through the release sub 204. In one embodiment, the anti-rotationcomponent 240 may be a plurality of pins.

FIG. 2A schematically illustrates the well control/string release tool70 being connected the workstring 9. The workstring 9 is set on thespider 4 s so that the well control/string release tool 70 can beattached to the workstring 9. In FIG. 2A, the well control/stringrelease tool 70 is set in a well control mode. In the well control mode,the plurality of load bearings 228 occupy the grooves 226 of the tubularsection 224 and the through holes 230 of the release sleeve 208 to jointhe handling sub 202 to the release sub 204 and the lock collar 218 isinserted between the handling sub 202 and the release sub 204 to preventunintentional detachment.

During drilling operation, such as casing run-in, the wellcontrol/string release tool 70 may be disposed on the rig floor 4 f. Incase of emergency, the well control/string release tool 70 may beattached to the workstring 9 while the workstring 9 is set on the spider4 s as shown in FIG. 2A. Well control procedures may be performed withthe well control/string release tool 70 attached to the workstring 9.

FIG. 2B is a schematic sectional view of the well control/string releasetool 70 during well control procedures. The well control/string releasetool 70 along with the workstring 9 is supported by a casing runningtool 242. Depending on the procedure and conditions, other tools, forexample drill pipe running tools, may be used to support the wellcontrol/string release tool 70 during well control procedure. The wellcontrol/string release tool 70 may be supported by internal slips 244extending from the casing running tool 242. Alternatively, other supportstructures, such as external slips, elevators, power swivels, may beused to support the well control/string release tool 70.

A nuzzle 248 may be extended into the well control/string release tool70. The nuzzle 248 may be used to circulate fluid during well controlprocedures. A sealing element 246 may be disposed inside the handlingsub 202 to prevent any fluid leaking from the well control/stringrelease tool 70 during well control procedures.

In the well control position shown in FIG. 2B, the plurality of loadbearings 228 occupy the combined space of the grooves 226 in the tubularbody 224 and the through holes 230 in the release sleeve 208, thuspreventing the tubular body 224 and the workstring 9 from slipping awayfrom the release sleeve 208. The release sleeve 208 is connected to thetubular connector 216 which may be suspended from the casing runningtool 242.

In the event that the well control procedures fails to control the wellpressure and closing the well is necessary, the well control/stringrelease tool 70 may be activated to release the workstring 9 from thecasing running tool 242, or whatever tool that is supporting theworkstring 9. FIG. 2C is a schematic sectional view of the wellcontrol/string release tool 70 during string release. To activate thewell control/string release tool 70, the landing sleeve 206 is first seton the spiders 4 s and the lock collar 218 may then be removed from thewell control/string release tool 70 to enable sliding motion between thelanding sleeve 208 and the release sleeve 206. The casing running tool242 may be used to support the weight of the workstring 9 so that thelock collar 218 is free from the weight of the workstring 9 and may beremoved from the gap between the landing sleeve 206 and the releasesleeve 208. The lock collar 218 may be removed manually or by hydraulicforce.

Once the lock collar 218 is removed, the tubular connector 216 and therelease sleeve 208 may be lowered relative to the landing sleeve 206. Inone embodiment, lowering the release sleeve 208 may be performed bylowering the casing running tool 242. Because the landing sleeve 206 issecured in place by the spider 4 s, the release sleeve 208 slidesrelative to the landing sleeve 206 as the release sleeve 208 is beinglowered. During sliding, the through holes 230 in the release sleeve 208come to align with the corresponding grooves 232 in the landing sleeve206. Under the weight of the workstring 9, the plurality of loadbearings 228 may be pushed radially outward into the grooves 232 and outof the grooves 226 in the tubular body 224. When the plurality of loadbearings 228 are out of the tubular body 224, the tubular body 224 andthe workstring 9 may fall down the wellbore under gravity. The handlingsub 202, which includes the landing sleeve 206, the release sleeve 208,and the tubular connector 216, remains on the deck while the release sub204 falls downhole with the workstring 9. The workstring 9 may fallunder blow out preventers, such as the BOP 30 a,u,b, in a matter ofseconds, and the wellbore can be closed out by the blow out preventersimmediately.

FIG. 3 is a schematic sectional view of a well control/string releasetool 70 a according to another embodiment of the present disclosure. Thewell control/string release tool 70 a is similar to the wellcontrol/string release tool 700 except that the well control/stringrelease tool 70 a includes a drillpipe adaptor 316. The drill pipeadaptor 316 may be coupled to the release sleeve 208 by a fast lock oran ACME connector. The drill pipe adaptor 316 may include a lower end302 configured to couple with the release sleeve 208 and an upper end304 configured to couple with a handling tool, such as a drilling tool.A well control/string release tool according to the present disclosuremay switch between the drillpipe adaptor 316 and the tubular connector216 of FIGS. 2A-2C according to the need of pressure and/or power duringa well control procedure.

FIG. 4 is a flow chart of a method 400 according to one embodiment ofthe present disclosure. The method 400 relates to well control and/orstring release operation on an offshore drilling system. In oneembodiment, the method 400 may be used to perform well control duringcasing running. The method 400 may be performed in an offshore drillingsystem, such as the drilling system 1 of FIGS. 1A-1C.

Box 410 of the method 400 includes monitoring well conditions duringoperation, such as running casing with a casing running tool. Box 410may be performed using any suitable methods with suitable tools. Duringcasing running, well conditions may be monitored and a trigger signalmay be sent when well control may be desired. For example, a triggersignal may be sent when a surge of pressure in the wellbore is detectedwhile running casing.

In Box 420, upon detecting a trigger signal or a well control condition,such as a kick in well pressure, a well control/string release tool,such as the well control/string release tool 70, 70 a, may be attachedto the workstring, for example a casing string. The well control/stringrelease tool may be attached to the workstring by first setting theworkstring on spider slips on the rig floor, and then attaching the wellcontrol/string release tool to the workstring with a tool on thedrilling system, such as a casing running tool or a drilling tool.

In Box 430, well control procedures may be performed through the wellcontrol/string release tool. During well control, suitable well-controlprocedures may be performed to retain the hydrocarbon in the productionzone and to prevent fractures on the walls of the wellbore. For example,various methods may be performed to control the pressure at the bottomof the wellbore so that the pressure at the bottom of the wellbore isslightly greater than the formation pressures. Fluids may be suppliedthrough the well control/string release tool during well controlprocedures. Well conditions, such as wellbore pressure, are constantlymonitored while well control procedures are performed.

In one embodiment, one or more components of the well control/stringrelease tool or the well control/string release tool to allow switchingof tools during well control. For example, a casing running tool may beused at an early stage of well control. When the well pressure exceedsthe operation range of the casing running tool, other tools, such as adrilling tool, may be used to continue the well control procedure. Inone embodiment, a component, such as the tubular connector 216, may bereplaced by another component, such as the drillpipe connector 316, toallow the well control procedure switching from a casing running tool toa drilling tool. Alternatively, the entire well control/string releasetool, such as the well control/string release tool 70, may be replacedby another well control/string release tool, such as the wellcontrol/string release tool 70 a. In Box 430, the well conditions may beconstantly monitored to determine whether there is a critical emergencywell control situation or/or whether the well control procedures aresuccessful.

If there is a critical emergency well control situation that calls forshutting in the well, the well control/string release tool may beactivated to drop the casing string in a controlled manner as shown inBox 440. As described with FIG. 2C, the casing string may be released byfirst setting the handling sub of the well control/string release toolon the spider, then removing the lock mechanism, such as the lock collar218, and releasing the casing string by lowering the casing runningtool, drilling tool, or any other tool that supports the casing stringduring well control. After releasing, the casing string will fall belowthe blow out preventers in a matter of seconds. Once the casing stringfalls below the blow out preventers, the well can be shut in by closingthe blow out preventers.

If the well control procedures in Box 430 succeed, the well conditionsrecover to allow normal operations, the well control/string release toolmay be removed from the workstring in Box 450.

Even though, the method 400 relates to using the well control/stringrelease tool of the present disclosure while running casing, the methodsaccording to present disclosure may be used in any suitable processesduring which releasing a workstring in a controlled manner may bedesired.

FIGS. 5A-5B are schematic sectional views of a well control/stringrelease tool 500 according to another embodiment of the presentdisclosure. The well control/string release tool 500 may be used in themethod 400 for well control and string release. FIG. 5A illustrates thewell control/string release tool 500 assembled in a well controlposition and FIG. 5B illustrates the well control/string release tool500 in a string release position. The well control/string release tool500 may include a handling sub 502 and a release sub 504. The releasesub 504 may be selectively released from the handling sub 502 at thestring release position.

The handling sub 502 may include a landing sleeve 506 and a releasesleeve 508. The landing sleeve 506 may have an inner tubular 516 and anouter tubular 517. The inner tubular 516 may be handled by a tool on therig, such as a casing running tool, a drill pipe running tool, a powerswivel, or the like. An annular volume 507 is formed between the innertubular 516 and the outer tubular 517. The release sleeve 508 isdisposed in the annular volume 507. A groove 512 may be formed on anouter wall of the upper tubular 516. A dog 514 may be inserted into thegroove 512 through the release sleeve 508 to prevent the release sleeve508 from moving relative to the inner tubular 516. A lock sleeve 518 maybe used to activate or release the dog 514. The lock sleeve 518 has alock inner diameter 518 a and a release inner diameter 518 b. The locksleeve 518 may slide along the release sleeve 508 so that the dog 514 isselectively biased towards the inner tubular 512 by either the lockinner diameter 518 a or the release inner diameter 518 b. A plurality ofholes 532 may be formed through the inner tubular 516 near a lower endof the annular volume 507. The plurality of holes 532 open to theannular volume 507. A plurality of load bearing balls 528 may be movablydisposed in the plurality of holes 532 to support or release the releasesub 504.

The release sub 504 may include a tool joint 520 for connecting with aworkstring, such as a casing string, a drill pipe string, on otherstrings. The release sub 504 has a tubular section 524 extending fromthe tool joint 520. The tubular section 524 may be disposed inside aninner diameter 515 of the inner tubular 516 and selectively attached tothe handling tool 502 by a weight bearing structure. In one embodiment,the weight bearing structure includes a groove 526 formed on an outersurface of the tubular section 524. The plurality of load bearing balls528 may partially protruding from the inner tubular 516 and occupy thegroove 526 to prevent the tubular section 524 from moving verticallyrelative to the inner tubular 516, thus, hanging the release sub 504onto the handling sub 502. The release sleeve 508 may be lowered intothe annular volume 507 to insert a portion of each load bearing ball 528into the groove 526. The release sleeve 508 may be moved up to allow theplurality of load bearing balls 528 to return into the annular volume507 to release the release sub 504. In one embodiment, the releasesleeve 508 may have a curved surface 530 for contacting the load bearingballs 528.

In one embodiment, a drill pipe connection 534 may extend from thetubular section 524. The tubular section 524 and the drill pipeconnection 534 may form an inner volume of the tubular section 524 toallow fluid communication with an inner volume of the workstring duringwell control.

In one embodiment, the release sub 504 may include a torque transmissionfeature 540 to allow torque transmission between the handling sub 502and the release sub 504. In one embodiment, the tubular section 524 mayhave one or more drain ports 544 formed therethrough. The drain ports544 may be through holes in the tubular section 524. The drain ports 544fluidly connect the inner volume the workstring to an exterior volume.During string release, if the workstring is full of fluid, the drainports 544 allow fluid in the workstring to flow out and enable stringdropping. In one embodiment, seal stacks 542 may be positioned above andbelow the drain ports 544 between the lease sub 504 and the handling sub502. The seal stacks 542 prevent fluid from leaking out from the innervolume of the release sub 502 during well control.

The well control/string release tool 500 may be set in the well controlposition shown in FIG. 5A while being attached to the workstring, duringwell control, and while being removed from the workstring. In the wellcontrol position, the lock sleeve 518 is pulled down to push and insertthe dog 514 in the groove 512. The dog 514 locks the release sleeve 508in the lowered position. At the lowered position, the release sleeve 508pushes the load bearing balls 528 against the groove 526 on the releasesub 502. Each load bearing ball 528 is partially in the release sub 504and partially in the handling sub 502. The load bearing balls 528prevent the release sub 504 and the handling sub 502 from relativemotion along the vertical direction.

To release the workstring attached to the release sub 504, the handlingsub 502 may be first secured to the rig while the well control/stringrelease tool 500 is in the well control position. For example spiderslips on the rig may be used to secure the handling sub 502 around thelanding sleeve 506. Then the lock sleeve 518 may be moved to the releaseposition shown in FIG. 5B. The lock sleeve 518 may be pulled up orotherwise moved so that the lock inner diameter 518 a is no longerpushing against the dog 514 allowing the dog 514 to pop out the groove512. The release sleeve 508 may move relative to the inner tubular 516.Without the release sleeve 508 fixed in the annular volume 507, the loadbearing balls 528 move radially outward into the annular volume 507under the weight of the release sub 504 and the workstring attached tothe release sub 504. With the load bearing balls 528 out of the groove526, the release sub 502 along with the workstring attached thereto mayfall under gravity and become released from the rig.

FIGS. 6A-6B are schematic sectional views of a well control/stringrelease tool 600 according to another embodiment of the presentdisclosure. The well control/string release tool 600 may be used in themethod 400 for well control and string release. FIG. 6A illustrates thewell control/string release tool 600 in assembled in a well controlposition and FIG. 6B illustrates the well control/string release tool600 in a string release position. The well control/string release tool600 may include a handling sub 602 and a release sub 604. The releasesub 604 may be selectively released from the handling sub 602 at thestring release position.

The handling sub 602 may include a landing sleeve 606 and a releasesleeve 608. The release sleeve 608 may be movably disposed inside thelanding sleeve 606. On or more dogs 614 may be inserted through thelanding sleeve 606 into a groove 612 formed on an outer diameter of therelease sleeve 608 to prevent the release sleeve 608 from movingrelative to the landing sleeve 606. A lock sleeve 618 may be used toactivate or release the one or more dogs 614. The lock sleeve 618 has alock inner diameter 618 a and a release inner diameter 618 b. The locksleeve 618 may slide along the landing sleeve 606 so that the dogs 614is selectively biased towards the release sleeve 608 by either the lockinner diameter 618 a or the release inner diameter 618 b.

One or more recesses 630 may be formed in an inner diameter of thelanding sleeve 606. The one or more recesses 630 are configured toreceive one or more load carrying dogs 628. The load carrying dogs 628are configured to support the weight of the release sub 604 and theworkstring attached to the release sub 604. Each dog 628 has a slantedsurface 631 for interacting with a slanted bottom surface 632 on therelease sleeve 608. When the release sleeve 608 moves down relative tothe landing sleeve 606, the slanted bottom surface 632 of the releasesleeve 608 pushes the dogs 628 radially outward into the recesses 630.

The release sub 604 may include a tool joint 620 for connecting with aworkstring, such as a casing string, a drill pipe string, on otherstrings. The release sub 604 has a tubular section 624 extending fromthe tool joint 620. The tubular section 624 may be disposed inside aninner diameter 615 of the release sleeve 608 and selectively attached tothe handling tool 602 by a weight bearing structure. In one embodiment,the weight bearing structure includes a groove 626 formed on an outersurface of the tubular section 624. The one or more dogs 628 maypartially enter into the groove 626 to prevent the tubular section 624from moving vertically relative to the landing sleeve 606, thus, hangingthe release sub 604 from the handling sub 602. The release sleeve 608may move up to allow a portion of each dog 628 into the groove 626. Therelease sleeve 608 may move down to push the dogs 628 into the recesses630 to release the release sub 504.

In one embodiment, a drill pipe connection 634 may extend from thetubular section 624. The tubular section 624 and the drill pipeconnection 634 may form an inner volume of the tubular section 624 toallow fluid communication with an inner volume of the workstring duringwell control. In one embodiment, the release sub 604 may include atorque transmission feature 640 to allow torque transmission between thehandling sub 602 and the release sub 604. In one embodiment, the tubularsection 624 may have one or more drain ports 644 formed therethrough.The drain ports 644 may be through holes in the tubular section 624. Thedrain ports 644 fluidly connect the inner volume the workstring to anexterior volume. During string release, if the workstring is full offluid, the drain ports 644 allow fluid in the workstring to flow out andenable string dropping. In one embodiment, seal stacks 642 may bepositioned above and below the drain ports 644 between the lease sub 604and the handling sub 602. The seal stacks 642 prevent fluid from leakingout from the inner volume of the release sub 602 during well control.

The well control/string release tool 600 may be in the well controlposition shown in FIG. 6A while being attached to the workstring, duringwell control, and while being removed from the workstring. In the wellcontrol position, the lock sleeve 618 is pulled down to push and insertthe dogs 614 in the groove 612. The dogs 614 lock the release sleeve 608in an upper position. At the upper position, the release sleeve 608allows the load carrying dogs 628 to be biased towards the groove 626 onthe release sub 602. Each load bearing dog 628 is partially in therelease sub 604 and partially in the handling sub 602. At this position,the load bearing dogs 628 prevent the release sub 604 and the handlingsub 602 from relative motion along the vertical direction.

To release the workstring attached to the release sub 604, the handlingsub 602 may be first secured to the rig while the well control/stringrelease tool 600 is in the well control position. For example spiders onthe rig may be used to secure the handling sub 602 around the landingsleeve 606. Then the lock sleeve 618 may be moved to the releaseposition shown in FIG. 6B. The lock sleeve 618 may be pulled up orotherwise moved so that the lock inner diameter 618 a is no longerpushing against the dogs 614 allowing the dogs 614 to pop out the groove612. The release sleeve 608 may move relative to the landing sleeve 606.The release sleeve 608 may be moved down relative to the landing sleeve606 to push the load bearing dogs 628 outward into the recesses 630. Inone embodiment, the release sleeve 608 may be moved down by applying adownward force to the release sleeve 608. For example, an upper tubular609 of the release sleeve 608 may be coupled to a top drive which maymove the release sleeve 608 downward. With the load bearing dogs 628 outof the groove 626, the release sub 602 along with the workstringattached thereto may fall under gravity and become released from therig.

FIGS. 7A-7C schematically illustrates a well control/string release tool700 according to another embodiment of the present disclosure. The wellcontrol/string release tool 700 may be used in the method 400 for wellcontrol and string release. FIG. 7A illustrates the well control/stringrelease tool 700 in assembled in a well control position. FIGS. 7B-7Cillustrate a sequence of tool releasing using the well control/stringrelease tool 700. The well control/string release tool 700 is similar tothe well control/string release tool 600 except that the wellcontrol/string release tool 700 has a two stage release sleeve 708 inplace of the release sleeve 608. The two stage release sleeve 708 movesthe load bearing dogs 628 from the release sub 604 in two steps, thus,further prevent accidental release of the workstring attached to releasesub 604.

The two stage release sleeve 708 includes an inner sleeve 752 and anouter sleeve 754. The inner sleeve 752 has a slanted bottom surface 756for interacting with the load bearing dogs 628. The outer sleeve 754 hasa slanted bottom surface 758 for interacting with the load bearing dogs628. When assembled, as shown in FIG. 7A, the inner sleeve 752 and theouter sleeve 754 are joined together by a releasable connector 750. Whenthe inner sleeve 752 and the outer sleeve 754 are joined together, theslanted bottom surfaces 756, 758 are at the different levels so thatonly one of the slanted bottom surfaces 756, 758 contacts the loadbearing dogs 628. In the embodiment shown in FIG. 7A, the outer sleeve754 has a groove 760 for receiving the dogs 614 which lock the two stagerelease sleeve 708 to the landing sleeve 606. The outer sleeve 754 alsohas a groove 762 for receiving the releasable connection 750. In oneembodiment, a groove 764 may be formed on an outer diameter of thetubular section 624. The groove 764 may be positioned to release thereleasable connection 750.

The well control/string release tool 700 may be in the well controlposition shown in FIG. 7A while being attached to the workstring, duringwell control and while being removed from the workstring. In the wellcontrol position, the lock sleeve 618 is pulled down to push and insertthe dogs 614 in the groove 760 on the outer sleeve 754. The dogs 614lock the two stage release sleeve 708 in an upper position where theslanted bottom surface 756 of the inner sleeve 752 contacts the loadbearing dogs 628. The slanted bottom surface 758 of the outer sleeve 754does not contact the load bearing dog 628. At the upper position, thetwo stage release sleeve 708 allows the load carrying dogs 628 to bebiased towards the groove 626 on the release sub 604. Each load bearingdog 628 is partially in the release sub 604 and partially in thehandling sub 602. At this position, the load bearing dogs 628 preventthe release sub 604 and the handling sub 602 from relative motion alongthe vertical direction.

To release the workstring attached to the release sub 604, the handlingsub 602 may be first secured to the rig while the well control/stringrelease tool 700 is in the well control position. For example a spideron the rig may be used to secure the handling sub 702 around the landingsleeve 606. Then the lock sleeve 618 may be moved to the releaseposition as shown in FIG. 7B. The lock sleeve 618 may be pulled up orotherwise moved so that the lock inner diameter 618 a is no longerpushing against the dogs 614 allowing the dogs 614 to pop out the groove760. The inner sleeve 752 and the outer sleeve 754 of the two stagerelease sleeve 708 may move together relative to the landing sleeve 606.

After the lock sleeve 618 is released, the inner sleeve 752 and theouter sleeve 754 may be moved down together relative to the landingsleeve 606 to push the load bearing dogs 628 radially outward into therecesses 630. The releasable connection 750 ensures that the innersleeve 752 and the outer sleeve 754 stay together. In one embodiment,the two stage release sleeve 708 may be moved down by applying adownward force to the two stage release sleeve 708. At this stage, theslanted bottom surface 756 of the inner sleeve 752 contacts and pushesthe load bearing dogs 628. However, the joint motion of the inner sleeve752 and the outer sleeve 754 may be stopped while the load bearing dogs628 are still inserted in the release sub 604 as shown in FIG. 7B. Inone embodiment, the joined motion may be stopped by the releasableconnection 750 when the releasable connection 750 springs into thegroove 764 and couples the inner sleeve 752 to the release sub 604.Alternatively, the joined motion may be stopped because the slantedbottom surface 756 reaches the end of the slanted surface 631 of theload bearing dogs 628. In the position shown in FIG. 7B, the loadbearing dogs 628 are partially removed from the release sub 604.

When the releasable connection 750 springs into the groove 764, theouter sleeve 754 becomes movable relative to the inner sleeve 752. Theouter sleeve 754 may be moved by itself further down so that the slantedbottom surface 758 reaches the slanted surface 631 and pushes the loadbearing dogs 628 radially outward. The outer sleeve 754 may be moveddown using a tool on the rig. As shown in FIG. 7C, the downward movementof the outer sleeve 754 may push the load bearing dogs 628 completelyout of the release sub 604 to release the workstring attached tothereon.

FIGS. 8A-8D schematically illustrates a well control/string release toolaccording to another embodiment of the present disclosure. The wellcontrol/string release tool 800 may be used in the method 400 for wellcontrol and string release. FIG. 8A illustrates the well control/stringrelease tool 800 in assembled in a well control position. FIGS. 8B-8Dillustrate a sequence of tool releasing using the well control/stringrelease tool 800.

The well control/string release tool 800 may include a handling sub 802and a release sub 804. The release sub 804 may be selectively releasedfrom the handling sub 802 at the string release position. The handlingsub 802 may include a landing sleeve 806 and a release sleeve 808. Therelease sleeve 808 may be movably disposed inside the landing sleeve806. The release sleeve 808 has one or more through holes 807. Eachthrough hole 807 has a slanted bottom 832. The slanted bottom 832 ishigher at the inner diameter and lower at the outer diameter.

One or more dogs 814 may be inserted through the landing sleeve 806 intoa groove 812 formed on an outer diameter of the release sleeve 808 toprevent the release sleeve 808 from moving relative to the landingsleeve 806. A lock sleeve 818 may be used to activate or release the oneor more dogs 814. The lock sleeve 818 may slide along the landing sleeve806 so that the dogs 814 are selectively activate or release the one ormore dogs 814.

One or more recesses 830 may be formed in an inner diameter of thelanding sleeve 806. Each recess 830 has a slanted bottom 829. Theslanted bottom 829 is higher at the inner diameter and lower towards theouter diameter. The one or more recesses 830 are configured to receiveone or more load carrying dogs 828. The load carrying dogs 828 areconfigured to support the weight of the release sub 804 and theworkstring attached to the release sub 804. Each load carrying dog 828may have a slanted lower surface 831 for interacting with the slantedbottom 832 on the release sleeve 808. Each load bearing dog 828 may havea flat upper surface 823 for load bearing. When the release sleeve 808moves up relative to the landing sleeve 806, the slanted bottom 832 onthe release sleeve 808 pushes the dogs 828 radially outward into therecesses 830.

The release sub 804 may include a tool joint 820 for connecting with aworkstring, such as a casing string, a drill pipe string, on otherstrings. The release sub 804 has a tubular section 824 extending fromthe tool joint 820. The tubular section 824 may be disposed inside theinner diameter of the release sleeve 808 and selectively attached to thehandling tool 802 by a weight bearing structure. In one embodiment, theweight bearing structure includes a groove 826 formed on an outersurface of the tubular section 824. The groove 826 may have a flat uppersurface 827 and a slanted lower surface 825. The slanted lower surface825 is lower at the outer diameter and higher towards the center axis.The slanted bottom 832, the slanted bottom 829, the slanted lowersurface 825, and the slanted lower surface 831 may have the same angleso that the load bearing dogs 828 may move from the groove 826 to therecess 830 by the release sleeve 808. The one or more dogs 828 maypartially enter into the groove 826 to prevent the tubular section 824from moving vertically relative to the landing sleeve 806, thus, hangingthe release sub 804 onto the handling sub 802. The release sleeve 808may move down to push the dogs 828 into the recesses 830 to release therelease sub 804.

The well control/string release tool 800 may be in the well controlposition shown in FIG. 8A while being attached to the workstring, duringwell control and while being removed from the workstring. In the wellcontrol position, the lock sleeve 818 is pulled down to push and insertthe dogs 814 in the groove 812. The dogs 814 lock the release sleeve 808in a lower position. At the lower position, the release sleeve 808allows the load carrying dogs 828 to be biased towards the groove 826 onthe release sub 804 so that each load bearing dog 828 is partially inthe release sub 804 and partially in the handling sub 802. At thisposition, the load bearing dogs 828 prevent the release sub 804 and thehandling sub 802 from relative motion along the vertical direction.

To release the workstring attached to the release sub 804, the handlingsub 802 may be first secured to the rig while the well control/stringrelease tool 800 is in the well control position. For example spiderslips on the rig may be used to secure the handling sub 802 around thelanding sleeve 806. Then the lock sleeve 818 may be moved to the releaseposition shown in FIG. 8B.

The release sleeve 808 may move up relative to the landing sleeve 806 asshown in FIG. 8C. As the release sleeve 808 moves up relative to thelanding sleeve 806, the slanted bottom 832 on the release sleeve 808pushes against the bottom surface 831 of the load bearing dogs 828causing the load bearing dogs 828 to move outward into the recesses 830in the landing sleeve 806. In one embodiment, the release sleeve 808 maybe moved up using a tool on the rig. As shown in FIG. 8C, the releasesleeve 808 may move the load bearing dogs 828 completely out of thegroove 826, thus, releasing the release sub 804 along with theworkstring attached thereto may fall under gravity and become releasedfrom the rig.

FIGS. 9A-9B schematically illustrates a well control/string release tool900 according to another embodiment of the present disclosure. The wellcontrol/string release tool 900 may be used in the method 400 for wellcontrol and string release. FIG. 9A is a schematic sectional side viewof the well control/string release tool 900 in assembled in a wellcontrol position. FIG. 9B is schematic sectional view of the wellcontrol/string release tool 900.

The well control/string release tool 900 may include a handling sub 902and a release sub 904. The release sub 904 may be selectively releasedfrom the handling sub 902 at the string release position. The handlingsub 902 may include a landing sleeve 906 and a release sleeve 908. Therelease sleeve 908 may be configured to connect with a top drive unit onthe rig. The release sub 904 may be connected to a workstring by anadaptor (not shown).

The release sub 904 may be a mandrel having torque keys 912 formed in anouter diameter 942. Key ways 913 matching the torque keys 912 may beformed in an inner surface 962 of the landing sleeve 906. The releasesub 904 and the landing sleeve 906 are coupled together by the torquekeys 912 and the key ways 913. One or more seal 914 may be disposedbetween the release sub 904 and the landing sleeve 906. The release sub904 may have a threaded portion 910 formed on an inner surface 944. Athreaded portion 911 may be formed on an outer surface 982 of therelease sleeve 908. Threads in the threads portion 911 match threads inthe threaded portion 912. The release sub 904 may be coupled to therelease sleeve 908 by the threaded portions 912 and 911. In oneembodiment, the thread portions 912, 911 may be connected by left handthreads, where turning clockwise breaks the connection and turningcounter clockwise makes the connection. One or more seal 916 may bedisposed between the release sub 904 and the release sleeve 908.

During operation, the well control/release tool 900 may be attached to aworkstring by connecting the release sub 904 to the top of a workstring.The release sleeve 908 of the well control/release tool 900 may beconnected to a top drive on the rig to perform well control operations.During well control operations, the threaded portions 912, 911 beartension loads and a portion of torsional loads. The key way 913 and thetorque keys 912 bear a portion of torsional loads.

To release the workstring attached to the release sub 904, the handlingsub 902 may be first secured to the rig while the well control/stringrelease tool 900 is in the well control position. For example spiderslips on the rig may be used to secure the handling sub 902 around thelanding sleeve 906. Then the threaded connection between the releasesleeve 908 and the release sub 904 may be broken up to release theworkstring. For example, the release sleeve 908 may be rotated clockwiseto break up the connection between the release sub 904 and the releasesleeve 908.

Embodiments of the present disclosure provide a tool comprising arelease sub configured to connect with an upper end of a workstring, ahandling sub configured to connect with a tubular handling tool disposedabove a wellbore, and one or more load bearing elements selectivelycoupled between the release sub and the handling sub.

In one or more embodiment, the release sub comprises a tubular sectionhaving a groove on an outer surface, and the groove is configured toreceive a portion of each of the one or more load bearing elements.

In one or more embodiment, the handling sub comprises a landing sleeve,and a release sleeve coupled to the landing sleeve, wherein the releasesleeve is positioned to allow the one or more load bearing elements outof the groove of the tubular section.

In one or more embodiment, the handling sub comprises a landing sleeve,and a release sleeve coupled to the landing sleeve, wherein the releasesleeve is positioned to move the one or more load bearing elements outof the groove of the tubular section.

In one or more embodiment, the handling sub further comprises a lock toselectively secure the landing sleeve to the release sleeve.

In one or more embodiment, the release sub further comprises a torquetransmission component.

In one or more embodiment, the handling sub further comprises a tubularconnector adapted to interact with a tool.

In one or more embodiment, the tubular section includes one or moredrain ports.

In one or more embodiment, the release sleeve comprises an inner sleeve,an outer sleeve, and a releasable connection coupled to the inner sleeveand the outer sleeve.

In one or more embodiment, the tool further comprises a Kelly valvecoupled to the tubular section.

In one or more embodiment, the one or more load bearing elementscomprise one or more load bearing dogs.

In one or more embodiment, the load bearing elements comprising a threadportion.

Embodiments of the present disclosure provide a method for operating awell. The method comprises attaching a well control/string release toolto a workstring, wherein the well control/release tool comprises arelease sub, a handling sub, and one or more load bearing elementsselectively coupled between the release sub and the handling sub, andperforming a well control procedure through the well control/stringrelease tool.

In one or more embodiment, the workstring is a casing string.

In one or more embodiment, attaching the well control/string releasetool comprises attaching an upper end of the workstring to the releasesub.

In one or more embodiment, the method further comprises monitoring wellcondition while performing the well control procedure.

In one or more embodiment, the method further comprises activating thewell control/string release tool to release the workstring upondetecting an emergency condition.

In one or more embodiment, the method further comprises removing thewell control/string release tool upon detecting a normal operationalcondition.

In one or more embodiment, activating the well control/string releasetool comprises securing the handling sub by spider slips, and moving theone or more load bearing elements out of the release sub.

In one or more embodiment, performing a well control procedure comprisescontrolling a well pressure using a casing running tool.

In one or more embodiment, the handling sub comprises a landing sleeve,and a release sleeve coupled to the landing sleeve, wherein the releasesleeve is positioned to allow the one or more load bearing elements outof the groove of the tubular section.

In one or more embodiment, performing a well control procedure furthercomprises connecting a drill pipe adaptor to the well control/stringrelease tool, and controlling the well pressure using a drilling tool.

In one or more embodiment, activating the well control/string releasetool further comprises releasing a releasable connection attachedbetween a releasing sleeve and a handling sleeve of the handling sub,and moving the release sleeve relative to the handling sleeve.

In one or more embodiment, moving the one or more load bearing elementsout of the release sub comprises moving the release sleeve with atubular handling tool disposed above a wellbore.

Embodiment of the present disclosure provides a method for operating awell, comprising attaching a well control/string release tool to aworkstring, wherein the well control/release tool comprises a releasesub attached to the workstring, a handling sub, and one or more loadbearing elements selectively coupled between the release sub and thehandling sub, and activating the well control/string release tool torelease the workstring upon detecting an emergency condition.

Embodiment of the present disclosure provides a drilling systemcomprising a rig, and a well control/string release tool disposed on afloor of the rig. The well control/string release tool comprises arelease sub, a handling sub, and one or more load bearing elementsselectively coupled between the release sub and the handling sub.

Embodiment of the present disclosure provides a method for operating awell, comprising attaching a well control/string release tool to aworkstring, performing a well control procedure through the wellcontrol/string release tool, and activating the well control/stringrelease tool to release the workstring upon detecting an emergencycondition.

While the foregoing is directed to embodiments of the presentdisclosure, other and further embodiments of the disclosure may bedevised without departing from the basic scope thereof, and the scope ofthe present invention is determined by the claims that follow.

1. A tool comprising: a release sub configured to connect with an upperend of a workstring; a handling sub configured to connect with a tubularhandling tool disposed above a wellbore; and one or more load bearingelements selectively coupled between the release sub and the handlingsub.
 2. The tool of claim 1, wherein the release sub comprises a tubularsection having a groove on an outer surface, and the groove isconfigured to receive a portion of each of the one or more load bearingelements.
 3. The tool of claim 2, wherein the handling sub comprises: alanding sleeve; and a release sleeve coupled to the landing sleeve,wherein the release sleeve is positioned to move the one or more loadbearing elements out of the groove of the tubular section.
 4. The toolof claim 3, wherein the handling sub further comprises a lock toselectively secure the landing sleeve to the release sleeve.
 5. The toolof claim 2, wherein the release sub further comprises a torquetransmission component.
 6. The tool of claim 3, wherein the handling subfurther comprises a tubular connector adapted to interact with a tool.7. The tool of claim 2, wherein the tubular section includes one or moredrain ports.
 8. The tool of claim 3, wherein the release sleevecomprises: an inner sleeve; an outer sleeve; and a releasable connectioncoupled to the inner sleeve and the outer sleeve.
 9. The tool of claim2, further comprising a Kelly valve coupled to the tubular section. 10.The tool of claim 1, wherein the one or more load bearing elementscomprise one or more load bearing dogs.
 11. The tool of claim 2, whereinthe handling sub comprises: a landing sleeve; and a release sleevecoupled to the landing sleeve, wherein the release sleeve is positionedto allow the one or more load bearing elements out of the groove of thetubular section.
 12. A method for operating a well, comprising:attaching a well control/string release tool to a workstring, whereinthe well control/release tool comprises: a release sub; a handling sub;and one or more load bearing elements selectively coupled between therelease sub and the handling sub; and performing a well controlprocedure through the well control/string release tool.
 13. The methodof claim 12, wherein attaching the well control/string release toolcomprises attaching an upper end of the workstring to the release sub;14. The method of claim 13, further comprising: monitoring wellcondition while performing the well control procedure.
 15. The method ofclaim 14, further comprising: activating the well control/string releasetool to release the workstring upon detecting an emergency condition.16. The method of claim 15, wherein activating the well control/stringrelease tool comprises: securing the handling sub by spider slips; andmoving the one or more load bearing elements out of the release sub. 17.The method of claim 16, wherein performing a well control procedurecomprises: controlling a well pressure using a casing running tool. 18.The method of claim 17, wherein performing a well control procedurefurther comprises: connecting a drill pipe adaptor to the wellcontrol/string release tool; and controlling the well pressure using adrilling tool.
 19. The method of claim 15, wherein activating the wellcontrol/string release tool further comprises: releasing a releasableconnection attached between a releasing sleeve and a handling sleeve ofthe handling sub; and moving the release sleeve relative to the handlingsleeve.
 20. The method of claim 19, wherein moving the one or more loadbearing elements out of the release sub comprises moving the releasesleeve with a tubular handling tool disposed above a wellbore.
 21. Themethod of claim 14, further comprising: removing the well control/stringrelease tool upon detecting a normal operational condition.
 22. Adrilling system, comprising: a rig; and a well control/string releasetool disposed on a floor of the rig, wherein the well control/stringrelease tool comprises: a release sub; a handling sub; and one or moreload bearing elements selectively coupled between the release sub andthe handling sub.
 23. A method for operating a well, comprising:attaching a well control/string release tool to a workstring; performinga well control procedure through the well control/string release tool;and activating the well control/string release tool to release theworkstring upon detecting an emergency condition.
 24. A method foroperating a well, comprising: attaching a well control/string releasetool to a workstring, wherein the well control/release tool comprises: arelease sub attached to the workstring; a handling sub; and one or moreload bearing elements selectively coupled between the release sub andthe handling sub; and activating the well control/string release tool torelease the workstring upon detecting an emergency condition.